Apparatus for Preventing Unintentional Valve Operation During Wireline Operations

ABSTRACT

A method of preventing valve operations which may inadvertently shear a wireline, causing a downhole tool string loss. Logic control of actuated valve control equipment in a wireline operation enables and disables or set valve states when a wireline is passing through dependent on tool string placement. Emergency override is available to shear wirelines and drop tool strings prior to valve operations to avoid possible interference with valve closures.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. § 119(e) fromco-pending U.S. Provisional Patent Application No. 62/825,304, by JasonPitcher, “Apparatus for Preventing Unintentional Valve Operations DuringWireline Operations” filed 28 Mar. 2019, which, by this statement, isincorporated herein by reference for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

REFERENCE TO SEQUENCE LISTING, A TABLE, OR A COMPUTER PROGRAM LISTINGCOMPACT DISC APPENDIX

Not Applicable.

BACKGROUND OF THE INVENTION Field of the Invention

The invention relates generally to wireline operations in drillingoperations. More particularly, the invention relates to instrumentingand monitoring wireline equipment to prevent unintentional valveoperation shearing a wireline.

Background of the Invention

Wireline operations are defined as any oil and gas exploration orproduction activity that involves lowering a tool, or plurality of tools(a tool string) into a well bore using a wire or braided cable. Braidedcables are usually referred to as wirelines and single strand cables arereferred to as slicklines. The reasons for making a distinction has todo with the technical challenge of forming a pressure seal around thedifferent surfaces, but is irrelevant for purpose of this discussion,and thus may be used interchangeably.

Wireline operations are used for a wide variety of purposes throughoutthe various phases of exploration and production activities. Duringthese exploration and production activities a well is usually underpressure, and care must be taken to avoid losing control of the well. Ablowout can be financially costly, and environmentally impactful, aswell as possibly causing human injury/fatality.

Moving equipment in and out of a wellbore with anywhere from 5,000 psito over 20,000 psi requires the use of pressure control devices as wellas experience and careful planning. Wireline operations require thewireline tools to be inserted and removed from the well in such a waythat pressure is constantly maintained. This is done through what isgenerally referred to as a lubricator.

A lubricator is a long, high-pressure pipe fitted to the top of awellhead or Christmas tree with a master valve to provide access to thewellbore. The lubricator is usually made up of a variety of elementsdepending on the task at hand, including, but not limited to: one ormore risers, optional tool traps, a head catcher, high-pressuregrease-injectors, adapters, and sealing elements.

The tool string is placed in the lubricator and the lubricator ispressurized to wellbore pressure. The master valve, and other valvescomprising the tree are then opened, enabling the tool string to enterthe wellbore. To remove the tools, the tool string is brought into thelubricator under wellbore pressure, the master valve is closed, thelubricator pressure is bled off, then the lubricator is opened to removethe tools.

A master valve is of such importance to well operation that there isusually an upper master valve and a lower master valve herein referencedcollectively as a single master valve. Additionally, a well is commonlyprotected against blowouts by one or more devices called blowoutpreventors generally various forms of actuated valves that are referredto as BOPs. BOPs are incorporated into a well stack or Christmas treeand elsewhere on the well. In the event of an emergency, BOPs close offthe well to contain the pressure and prevent the escape ofenvironmentally damaging fluids. The BOPs close off the well through theuse of hydraulic shear seal rams, which are powerful enough to sheardrill pipe and crush any tool string in the process.

Federal and International laws require lubricators used in wirelineoperations also include one or more wireline rams (AKA wireline valvesor wireline BOPs) between the lubricator and the wellbore, which mayserve as or supplement a master valve. This is in addition to the BOPsalready incorporated into the well. Wireline rams may be wirelinesealing rams or blind shear rams. Wireline sealing rams have smallopenings through which wireline may pass when the rams are closed. Blindshear rams are similar to the shear seal rams described above, butwireline operation equipment may also include wire cutters which severthe wireline during an emergency allowing the tool string to fall downthe wellbore.

BOPs are a primary safety element in preventing well blowout. Due to thehigh impact their malfunction could have on the environment and/orworker safety, BOPs are government regulated. BOP focused governmentregulations require routine maintenance, regular operations, andextensive testing, sometimes to a daily level. Additionally, BOPs areoften remotely activated because of the likely inhospitable state oftheir immediate surroundings in the instances their uses provedmandatory.

Given the circumstances, it is not surprising that a common failureduring wireline operations is the accidental and/or unintentionalactivation of a valve in the stack or elsewhere along the line, causingsevering of the wireline. The result is damaged or lost equipment, timedelays while fishing operations occur, or new equipment is procured forthe scheduled wireline operations. While sometimes the valve operationmay be necessary to avert an emergency situation, it is desirable toprevent the avoidable instances. Wireline operations and the resultingtime a well is not producing can already be expensive without the costincreases of unnecessary delays and mistakes.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an exemplary arrangement of common components typicallyincorporated into a lubricator, though variations would be dictated bythe specific intended task.

FIG. 2 illustrates a lubricator supported atop a Christmas tree by atelescoping gin pole.

FIGS. 3A and 3B show an instrumented riser for detecting the presence ofa tool string in accordance with an exemplary embodiment of theinnovation.

FIGS. 4A and 4B show alternative embodiments of instrumenting alubricator riser for detecting the presence of a tool string within theriser's internal cavity in accordance with an exemplary embodiment ofthe innovation.

FIG. 5 shows a partial cutaway view of a manually operated tool trapinstrumented in accordance with an exemplary embodiment of theinnovation.

FIG. 6 shows a partial cutaway view of a dual option mechanized ormanually operated tool trap instrumented in accordance with an exemplaryembodiment of the innovation.

FIG. 7 shows an exemplary configuration for utilizing instrumentedrisers and electronic controllers, for an implementation in accordancewith the innovation presented herein.

DETAILED DESCRIPTION OF THE INNOVATION

This innovation seeks to prevent the wasted resources caused byinadvertent or unintentional closing of hydraulic operated frac valveswhile wireline tool strings are deployed by instrumenting the lubricatorto monitor the deployment of a tool string, and selectively disablehydraulic frac valves through which the wireline passes. The sameteachings may equally be applied to other types of wireline operations.

As an additional advantage, other valves, including BOPs may also beselectively disabled in similar fashion, anywhere along the line whereactuators may be controlled. This includes valves which areelectrically, hydraulically, or pneumatically actuated, or valves whereactuation is controlled by electrical, hydraulic, or pneumatic controlsignals. In another embodiment the control method may be by manipulationof the motive power source for valves.

Manually operated valves may also be controlled by setting and removinginterlocks or providing physical indicators to operating personnel ofdesired activity. One skilled in the arts would appreciate the extensiveselection of equipment and the wide range of options for operations, indeployment on surface, subsea, or sub-surface and control optionsincluding manual, local, automatic, and/or remote.

For simplicity the system is described as enabling or disablinghydraulic valve operations. This may range from power control ofhydraulic pumps, their control equipment, disabling or interruptingcontrol signals, setting local worker lockouts, or simply notifying anoperator the valve is unavailable. All of these details can beappreciated by one skilled in the art, and therefor are outside thescope of this disclosure.

The following methods describe control of hydraulically actuated valvesduring wireline fracturing operations unless otherwise indicated by thecontext. While one skilled in the art would appreciate the applicationto many configurations, the exemplary use is a lubricator with aplurality of risers for holding a tool string above the wellhead valveprior to and after wireline operations. A tool trap at the lower end ofthe lubricator is connected between the risers and a master valveleading to the well bore. Also included are a plurality of otherhydraulically operated valves, including, but not limited to wirelineBOPs and Well BOPs, all of which may be collectively references asarticulated valves or BOPs.

The wireline or slickline exits the top of the lubricator thorough agrease injection control head (typically needed for wirelines, but notslicklines) then through a line wiper and a stuffing box, finallypassing over a sheave. The wireline or slickline then passes through afloor block (also known as a hay pulley) to bring the wireline down to aposition where it is horizontal from the tree to the drum reel/loggingtruck/wireline rig. This shifts the pulling force from the top of thelubricator to the base of the tree reducing the side loading on thelubricator.

Once positioned, the lubricator can be hydrostatic tested, then thewellhead's master valve is opened, and the tool string is inserted intothe wellbore. To remove the tool string, the process is essentiallyreversed. The wireline draws the tool string up the wellbore and intothe lubricator's risers. The master valve is closed, and pressure isreduced in the riser so the lubricator can be taken from the stack andthe tool string removed.

The innovation includes the use of one or more sensor(s) instrumentingthe lubricator to monitor the tool string. In the preferred embodiment,a sensor mounted to the lubricator, identifies when the tool stringoccupies the riser. Logic control such as a programmable controller, acomputing device, or specialized electronic circuitry disables actuatedvalves in the tool string path. In other embodiments the circuitry mayonly disable certain operations of the actuated valves, while allowingothers to function. In another embodiment, the circuitry may actuatemore or more of the actuated valves to be positioned in a desiredconfiguration.

In another embodiment, if valves are positioned outside the immediatearea of the lubricator, additional monitoring of the tool stringlocation (for example by knowing the length of the wireline orslickline) would allow for disabling of actuated valves based onproximity of the control valve to the tool string or its attachedwireline.

One skilled in the art would appreciate that monitoring may be via anelectronic sensor having a physical triggering element such as a contactswitch, an electrical probe, or other sensing element that isrepositioned, deformed, excited, activated, or otherwise triggered bythe presence (or absence) of a proximate tool string.

In another embodiment, electrical induction may be employed by sensorsto non-intrusively detect the presence/absence of equipment in thelubricator. Such an embodiment would have the additional advantage ofnot compromising the strength of the high-pressure containment vessels.Sensor triggering elements may detect the tool string through alterationof monitored characteristics such as optical interruption, magneticinduction, electrical conduction, acoustical resonance, etc.

However, in such an embodiment, care would be required to ensure sensorsdo not confuse the presence of a tool string with that of the wirelineor slickline passing through the lubricator. One skilled in the artswould understand sensitivity adjustment and/or calibration procedures toidentify a substantial mass difference or otherwise identify particularmaterial compositions. The preferred embodiment reduces potential falsetriggers by utilization of a plurality of sensors, the specificquantity, deployment, configuration being depending on the reliabilityof the sensory method employed.

As an example, a contact switch extending outward from an interior walltoward the center of a riser would be deflected by a tool stringoccupying that interior space. An optical interrupter positioned acrossthe interior of a riser would likewise detect a tool string occupyingthe interior space.

In another example, a plurality of optical interrupters may bepositioned, such that all of the sensors would not be impeded by a toolstring. This allows comparisons between the plurality of interrupters todistinguish true and false triggers or identify sub-optimal conditionsimpairing reliable detection.

In another example, the movement of a tool string, (usually having agenerally cylindrical shape and primarily of metallic composition) caninduce an electro-magnetic change in a coil sensor. One skilled in thearts would recognize other characteristics that may be monitored bysensors for varying situations.

Tool strings comprised of electronics, hydraulics, and or othercomponents which may move, change, adjust, or otherwise produceemissions that can be detected by sensors specific to the configuration.In a preferred embodiment, the sensor utilized may be configurableduring deployment for a situation dictated by the specific equipment.

In another embodiment the sensors may detect movement of the tool stringsuch as induction of an electrical/magnetic signal as a tool stringmoves past the sensor inducing a change to a triggering element throughthe riser to a sensor attached to the external surface. One skilled inthe arts would appreciate that a plurality of such sensors and the ordertriggered could identify direction of movement.

As an example, an inductive sensor would detect change to a magneticfield inducted by a moving tool string. Two optical sensors placed atdifferent points along the length of a riser would allow detection of atool string leaving or entering the lubricator and determine which hadoccurred by the order of their triggering.

In another embodiment, sensor may be removably attached to the riser'sexternal surface, such as by Velcro™ or elastic bands, adhesive, clamps,etc. In another embodiment the sensors may be incorporated into aconnector sub to be installed between other components in the lubricatorassembly. In another embodiment, sensors may be positioned above andbelow the tool trap or may work in conjunction with the tool trap's flapoperation to detect tool string movement.

For example, a logic control may monitor tool trap operations todetermine state changes. When the tool trap opens, it is possible forthe tool string to pass. Therefore, an immediate check of the sensor todetermine that the tool string is in the riser indicates it may be aboutto enter the wellbore. In response, the logic control would disablevalve closing, and possibly verify the positions of various actuatedvalves before enabling other equipment or signaling clearance for thetool string to enter the wellbore.

When the tool trap closes, a check of the sensor showing the tool stringis in the riser means it is essentially trapped there, unable to moveinto the wellbore. So, it is safe for the logic control to enable allvalve controls, and optionally trigger closure of the master valve.

This logic ensure actuated valves are disabled before the tool stringbegins leaving the riser and are not enabled until the tool string issecured back in the riser. In another embodiment, the logic may beenhanced to control specific operations, to allow actuated valveclosings are disabled preventing tool string damage, but openings arecontrolled by users.

In another embodiment, the logic may be further enhanced to automatevalve actuations, ensuring a clear passage into the wellbore, ordelaying openings until the tool string position requires a valveactivation. An alternative lubricator may utilize a wire cutterconfigured to monitor BOP control signals, emergency sensors, or manualswitches which signal a need to override wireline operations. Anoverride, as described above, could be configured for emergencypurposes. The act of someone being required to initiate an overrideensures the valve operation was intentional and necessary, rather thancarelessness.

By implementing an override for emergencies, the control logic can, inresponse to an override signal, if the tool string is not in thelubricator: 1) activate the wireline cutter, 2) delay to allow the toolstring to drop, then 3) close the master valve and 4) enable all otheractuated valves that may be disabled by the logic control, and 5)optionally move one or more actuated valves a pre-programmed position.This allows the safety measure of BOPs to operate in an emergency butcontrolled by wireline operators aware of current situations ratherthan, for example, as an automated test triggered by remote operatorsunaware of current operations.

The delay between activating the wireline cutter and closing the mastervalve/enabling the BOPs may be minimal, or substantially non-existent.The intent of a delay is to allow the tool string to fall down the wellbore, pulling the severed wireline free of valve bodies, which may becompromised by the presences of the wireline or tool string. This isbecause the specific location of the tool string in not known, only thatit is not in the lubricator, and therefore it may potentially be in aposition compromising to BOP operations.

DETAILED DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an exemplary arrangement of common components typicallyincorporated into a lubricator, though variations would be dictated bythe specific intended task. The lubricator's (100) bottom element is awell head flange adapter (40) to mate the lubricator (100) to a wellhead, Christmas tree, diverter, drilling platform, etc., (“thewellbore”).

The purpose of the lubricator (100) is to allow wireline operations tointroduce tool strings into the well bore. A well has variousconfigurations and locations for connection, but a lubricator (100) mayhave its own controls/master valve(s) (35). These master valve(s) (35)may vary in number, type, and arrangement but serve the purpose ofclosing off the lubricator (100) from the wellbore. They also may be ofmanual, electrical, or hydraulic operation, and must be operationallytested after installation.

A tool trap (30) is generally positioned above the master valve (35) toprotect its inner seals from damage caused by a tool string's impact.The tool trap (30) also prevents the loss of a tool string down awellbore if the wire strips. A tool trap (30) may be manually,electrically, or hydraulically operated, and generally is configured toreturn to and remain in a closed position after activation.

A lubricator's riser or simply riser (20) allows the wireline toolstring to be raised above the master valve (35) prior to and afterwireline operations and therefore enable the master valve (35) to beopened and closed allowing entry of the tool string into the wellbore,and close off pressure upon its exit from the well bore.

The functional requirements of master valve (35) logically require therisers (20) to be positioned so as to allow the tool string to be liftedabove the BOPs and master valve (35) to close off the wellbore duringwireline operations.

Risers (20) may also be supplemented with the inclusion of othercomponents: including but not limited to: wire cutter, tool clamp, toolcatcher, etc., none of which are shown here for simplicity. Thelubricator (100) is generally capped with a grease injection controlhead (10) or a stuffing box (7) and sheave/pulley (5) for introductionof the wireline, which may be mated to the lubricator (100) by a subadapter (15).

FIG. 2 illustrates a lubricator supported atop a Christmas tree by atelescoping gin pole. A gin pole (60) is attached to a Christmas tree(50) to support a rope block (55) that lifts and supports a lubricator(100) for connection of it's well head adapter flange (40) to the top ofthe Christmas tree (50). Once a lubricator (100) is positioned, awireline (70) attached to a tool string located in the lubricator's(100) risers (20, not labeled) can be used to move a tool string in andout of the wellbore.

A hay-block or floor pulley (65) is generally used to direct thewireline (70) down to a position where it is horizontal to the Christmastree (50). This shifts the point of wireline (70) pulling force from thetop of the lubricator (100) down toward the master valve (35) andadapter flange (40) near the well head's tree (50) reducing side loadingof the lubricator (100).

FIGS. 3A and 3B show an instrumented riser for detecting the presence ofa tool string in accordance with an exemplary embodiment of theinnovation. A riser (20, see previous FIG.) may be instrumented withsensors (210) to create an instrumented riser (200). The sensors (210)detect the presence or absence of a tool string (150) within theinstrumented riser (200).

FIGS. 3A and 3B show an embodiment of a physically switched sensor(210A) which comprises a physical plunger (215) shrouded behind aguiding spring/shield (220). The plunger (215) depresses to switch thesensor (210A) indicating the absence or presence of a tool string (150)within the instrumented riser (200). Entry of the tool string (150),deflects the spring/shield (220) which depresses the plunger (215)triggering the sensor (210A). Exiting of the tool string (150), allowsthe plunger (215) to reset the spring/shield (220) toward the middle ofthe riser's (200) internal cavity.

FIGS. 4A and 4B show alternative embodiments of instrumenting alubricator riser for detecting the presence of a tool string within theriser's internal cavity in accordance with an exemplary embodiment ofthe innovation. Sensors (210) in this embodiment have emitters (210B)and detectors (210C) which transmit (255) across the interior space ofthe riser (200). A tool string (150) interrupts the signal (255)indicating the presence of the tool string (150).

In another embodiment sensors (210) may be one or more passive receivers(210D) positioned along the external surface of a riser (200). Thesesensors (210) may detect sound, magnetism, electrical emissions,inductance, etc. through the riser (200) body.

FIG. 5 shows a partial cutaway view of a manually operated tool trapinstrumented in accordance with an exemplary embodiment of theinnovation. A tool trap (30, see prior FIG.) is instrumented with asensor (330) to create an instrumented tool trap (300). A sensor (330)is triggered by changing the position of the flapper (340).

Flappers (340), shown here in the open position, are generallyconfigured to be stable in the closed position. The embodimentillustrated shows a manual handle (310) lifted to open the flapper (340)and trigger the sensor (330). Releasing the handle (310) causes it todrop, returning the flapper (340) to the closed position, which is alsodetected by the sensor (330). In one embodiment the sensor may bepassive so it must be polled to determine current position. In anotherembodiment an active sensor may transmit a signal upon changes in state.

FIG. 6 shows a partial cutaway view of a mechanized or manually operatedtool trap instrumented in accordance with an exemplary embodiment of theinnovation. The instrumented tool trap's (300′) sensor (330) detects theposition of the flapper (340).

The embodiment illustrated has an activator (320) which operates thesame mechanism as the manual handle (310) to open the flapper (340)detected by the sensor (330). Releasing the handle (310) orde-energizing the activator (320) causes the flapper (340) to return tothe closed position, again detected by the sensor (330).

FIG. 7 shows an exemplary configuration for utilizing instrumentedrisers and electronic controllers for an implementation in accordancewith the innovation presented herein. The control system (400)implementation illustrated has a control unit (410) which implements aprogrammable logic system having input signals (420 & 420′) from sensors(210, and 330, internal to 300) and output signals (430, 430′, & 430″)for controlling various functions.

In the illustrated system (400), a dedicated logic controller regularlyreads the sensors (210) of the instrumented riser (200). Upon detectingan empty riser (200) the controller sends output signals (430 & 430′) toselectively disable or manipulate actuated valves (35 & 45). This may bea direct signal (430) to a master valve (35), or an indirect signal(430′) to a hydraulic unit (440), or other controller providinghydraulic motive power for operations (450) to BOPs (45).

In an alternative implementation of the illustrated system (400), adedicated logic controller may be triggered by an input signal (420′)from an instrumented tool trap (300) when opened by either the hydraulicmechanism or the manual handle (310). Upon sensing the tool trap (300)has opened, the control unit (410) sends output signals (430 & 430′)disabling the one or more operations of various actuated valves (35 &45). In an embodiment, the control unit (410) is configured to openand/or disable actuated valves (35 & 45) to prevent closure during toolstring work of a wireline operation involving a tool string deployeddown a wellbore.

When the tool trap (300) flapper (340) closes, the control unit (410)reads the sensor(s) (210) of the instrumented riser (200). If the toolstring (150, not shown) is detected, then the valves may be enabled.Otherwise they remain disabled. So, the actuated valves are only enabledupon closing of the tool trap (300) flapper (340) and confirmation ofthe tool string (150, not shown) being in a safe location.

An override command in the control unit (410) may exist for emergencies.This override command can be trigger by other sensors, a manual panicswitch, a dead-man switch, or other situations indicating an emergencyrequiring close off of a well. The control unit (410) first detects ifthe tool string (150, not shown) is in the riser (200) and the tool trap(300) is closed, which would mean any BOPs should be enabled. However,the control unit (410) may also be configured to signal the BOPs toclose off the well in response to an override command from the controlunit (410) rather than waiting for secondary activation of the BOPs.

If the control unit (410) does not detect the tool string (150, notshown) in the riser (200), it would first send a command (430″) to thewireline cutter (215) to sever the wireline and drop the tool string(150) down the wellbore before proceeding with the valve operationsdescribed above.

The diagrams represent exemplary embodiments of the present innovationand are provided as examples which should not be construed to limitother embodiments within the scope of the innovation. Physical elementsshould not be interpreted as to-scale and should not be construed tolimit the innovation to the particular proportions, quantities, orconfigurations illustrated. Elements illustrated in singularity may beimplemented in a plurality. Elements illustrated in plurality may varyin count. Illustrated forms may vary in detail, and any numerical datavalues provided, or other specific information is illustrative ofpossible implementations to be interpreted in the broadest scopepossible and not limiting of the innovation. Numerous variations andmodifications will become apparent to those skilled in the art once theabove disclosure is fully appreciated. It is intended that the followingclaims be interpreted to embrace all such variations and modifications.

I claim:
 1. An apparatus for wireline operations comprising: alubricator having one or more risers; an optional tool trap; one or moresensors for detecting a tool string; one or more actuated valves, onebeing a master valve between the lubricator and the wellbore; aprogrammable logic system; wherein the logic system is programmed tomonitor the sensor, and enable or disable operation of the one or moreactuated valves.
 2. An apparatus as described in claim 1 wherein the oneor more actuated valves are electrically, hydraulically, orpneumatically actuated.
 3. An apparatus as described in claim 1 whereinenable or disable operation of a valve comprises controlling an energysource of the articulated valve.
 4. An apparatus as described in claim 1wherein the one or more actuated valves are manually operated valveswith actuated interlocks to restrict manual operations.
 5. An apparatusas described in claim 4 wherein the articulated interlocks comprise anindicator to authorize or prohibit manual operation of the valve.
 6. Anapparatus as described in claim 3 wherein the logic system furthercomprises: an override, wherein the override: enables energy sources toone or more actuated valves; closes the master valve, and optionallysets one or more of the actuated valves to known states.
 7. An apparatusas described in claim 1 wherein the sensors detect the presents orabsence of the tool string in one or more of the risers.
 8. An apparatusas described in claim 1 wherein the sensors detect the movement of thetool string past one or more of the sensors.
 9. An apparatus asdescribed in claim 8 wherein a plurality of sensors detecting themovement of the tool string determines the direction of the movement ofthe tool string.
 10. An apparatus as described in claim 9 wherein thesensors identify the movement of the tool string into or out of the oneor more risers.
 11. An apparatus as described in claim 9 wherein thesensors identify the movement of the tool string through the tool trap.12. An apparatus as described in claim 1 wherein a sensor is mechanical.13. An apparatus as described in claim 1 wherein a sensor is magnetic.14. An apparatus as described in claim 1 wherein a sensor is passive.15. An apparatus as described in claim 1 wherein a sensor is removablyattached to an external surface of the lubricator.
 16. An apparatus asdescribed in claim 1 wherein a sensor is internal to the lubricator. 17.An apparatus as described in claim 8 wherein the lubricator furthercomprises a connector sub having sensors.
 18. An apparatus as describedin claim 17 wherein the connector sub is between two risers.
 19. Anapparatus as described in claim 17 wherein the connector sub is betweenthe lowest riser and the tool trap.
 20. A method of preventing valveoperations during wireline operations comprising: monitoring themovement and/or position of a tool string; determining the relationshipof the tool string to one or more actuated valves; disconnecting orconnecting motive power to the one or more actuated valves.